Api rp 2a wsd 2014 (american petroleum institute)

This publication serves as a guide for those who are concerned with the design and construction of new fixed offshoreplatforms and for the relocation of existing platforms used for the d

Fixed Offshore Platforms—Working Stress Design

API RECOMMENDED PRACTICE 2A-WSD TWENTY-SECOND EDITION, NOVEMBER 2014

API publications necessarily address problems of a general nature With respect to particular circumstances, local,state, and federal laws and regulations should be reviewed.

Neither API nor any of API's employees, subcontractors, consultants, committees, or other assignees make anywarranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of theinformation contained herein, or assume any liability or responsibility for any use, or the results of such use, of anyinformation or process disclosed in this publication Neither API nor any of API's employees, subcontractors,consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights.API publications may be used by anyone desiring to do so Every effort has been made by the Institute to assure theaccuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, orguarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss ordamage resulting from its use or for the violation of any authorities having jurisdiction with which this publication mayconflict

API publications are published to facilitate the broad availability of proven, sound engineering and operatingpractices These publications are not intended to obviate the need for applying sound engineering judgmentregarding when and where these publications should be utilized The formulation and publication of API publications

is not intended in any way to inhibit anyone from using any other practices

Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard

is solely responsible for complying with all the applicable requirements of that standard API does not represent,warrant, or guarantee that such products do in fact conform to the applicable API standard

All rights reserved No part of this work may be reproduced, translated, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher Contact the

Publisher, API Publishing Services, 1220 L Street, NW, Washington, DC 20005.

Copyright © 2014 American Petroleum Institute

This document contains engineering design principles and good practices that have evolved during the development

of offshore oil resources Good practice is based on good engineering; therefore, this recommended practice consistsessentially of good engineering recommendations In no case is any specific recommendation included that could not

be accomplished by presently available techniques and equipment Consideration is given in all cases to the safety ofpersonnel, compliance with existing regulations, and antipollution of water bodies U.S customary (USC) conversions

of primary metric (SI) units are provided throughout the text of this publication in parentheses, for example, 150 mm(6 in.) Most of the converted values have been rounded for most practical usefulness; however, precise conversionshave been used where safety and technical considerations dictate In case of dispute, the SI units should govern.Offshore technology continues to evolve In those areas where the committee felt that adequate data were available,specific and detailed recommendations are given In other areas, general statements are used to indicate thatconsideration should be given to those particular points Designers are encouraged to utilize all research advancesavailable to them As offshore knowledge continues to grow, this recommended practice will be revised It is hopedthat the general statements contained herein will gradually be replaced by detailed recommendations

Reference in this document is made to the 1989 edition of the AISC Specification for Structural Steel Buildings— Allowable Stress Design and Plastic Design The use of later editions of AISC specifications is specifically not

recommended for design of offshore platforms The load and resistance factors in these specifications are based oncalibration with building design practices and may not be applicable to offshore platforms Research work is now inprogress to incorporate the strength provisions of the new AISC code into offshore design practices

In this document, reference is made to AWS D1.1/D1.1M:2010, Structural Welding Code—Steel While use of this

edition is endorsed, the primary intent is that the AWS code be followed for the welding and fabrication of fixed offshoreplatforms However, where specific guidance is given in this API document, this guidance should take precedence This edition supersedes the 21st Edition dated December 2000, as well as Errata and Supplement 1 dated December

2002, Errata and Supplement 2 dated September 2005, and Errata and Supplement 3 dated October 2007 Revisionbars are not used for this edition for clarity because of the extensive document reorganization outlined in theIntroduction

The verbal forms used to express the provisions in this recommended practice are as follows:

— the term “shall” denotes a minimum requirement in order to conform to the recommended practice,

— the term “should” denotes a recommendation or that which is advised but not required in order to conform to therecommended practice,

— the term “may” is used to express permission or a provision that is optional,

— the term “can” is used to express possibility or capability

Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for themanufacture, sale, or use of any method, apparatus, or product covered by letters patent Neither should anythingcontained in the publication be construed as insuring anyone against liability for infringement of letters patent.This document was produced under API standardization procedures that ensure appropriate notification andparticipation in the developmental process and is designated as an API standard Questions concerning theinterpretation of the content of this publication or comments and questions concerning the procedures under whichthis publication was developed should be directed in writing to the Director of Standards, American PetroleumInstitute, 1220 L Street, NW, Washington, DC 20005 Requests for permission to reproduce or translate all or any part

API Standards Department, telephone (202) 682-8000 A catalog of API publications and materials is publishedannually by API, 1220 L Street, NW, Washington, DC 20005.

Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW,Washington, DC 20005, standards@api.org

1 Scope 1

2 Normative References 1

3 Terms, Definitions, Acronyms, and Abbreviations 2

3.1 Terms and Definitions 2

3.2 Acronyms and Abbreviations 4

4 Planning 5

4.1 General 5

4.2 Operational Considerations 5

4.3 Environmental Considerations 7

4.4 Site Investigation-Foundations 13

4.5 Selecting the Design Environmental Conditions 14

4.6 Platform Types 16

4.7 Exposure Categories 18

4.8 Platform Reuse 20

4.9 Platform Assessment 20

4.10 Safety Considerations 20

4.11 Regulations 21

5 Design Criteria and Procedures 22

5.1 General 22

5.2 Loading Conditions 23

5.3 Design Loads 24

5.4 Fabrication and Installation Forces 51

6 Structural Steel Design 56

6.1 General 56

6.2 Allowable Stresses for Cylindrical Members 57

6.3 Combined Stresses for Cylindrical Members 63

6.4 Conical Transitions 68

7 Strength of Tubular Joints 73

7.1 Application 73

7.2 Design Considerations 73

7.3 Simple Joints 79

7.4 Overlapping Joints 83

7.5 Grouted Joints 84

7.6 Internally Ring-stiffened Joints 85

7.7 Cast Joints 85

7.8 Other Circular Joint Types 85

7.9 Damaged Joints 86

7.10 Noncircular Joints 86

8 Fatigue 86

8.1 Fatigue Design 86

8.2 Fatigue Analysis 86

8.3 Stress Concentration Factors (SCFs) 88

8.4 S-N Curves for All Members and Connections, Except Tubular Connections 89

8.5 S-N Curves for Tubular Connections 90

8.6 Fracture Mechanics 93

9 Foundation Design 93

9.1 General 93

9.2 Pile Foundations 93

9.3 Pile Design 95

9.4 Pile Capacity for Axial Compression Loads 96

9.5 Pile Capacity for Axial Pullout Loads 97

9.6 Axial Pile Performance 97

9.7 Soil Reaction for Axially Loaded Piles 98

9.8 Soil Reaction for Laterally Loaded Piles 98

9.9 Pile Group Action 99

9.10 Pile Wall Thickness 100

9.11 Length of Pile Sections 103

9.12 Shallow Foundations 103

10 Other Structural Components and Systems 104

10.1 Superstructure Design 104

10.2 Plate Girder Design 105

10.3 Crane Supporting Structure 105

10.4 Grouted Pile-to-structure Connections 106

10.5 Guyline System Design 110

11 Material 112

11.1 Structural Steel 112

11.2 Structural Steel Pipe 113

11.3 Steel for Tubular Joints 114

11.4 Cement Grout and Concrete 118

11.5 Corrosion Protection 118

12 Drawings and Specifications 118

12.1 General 118

12.2 Conceptual Drawings 119

12.3 Bid Drawings and Specifications 119

12.4 Design Drawings and Specifications 119

12.5 Fabrication Drawings and Specifications 120

12.6 Shop Drawings 121

12.7 Installation Drawings and Specifications 121

12.8 As-built Drawings and Specifications 121

13 Welding 122

13.1 General 122

13.2 Qualification 123

13.3 Welding Details 124

13.4 Records and Documentation 125

14 Fabrication 125

14.1 Assembly 125

14.2 Corrosion Protection 131

14.3 Structural Material 131

14.4 Loadout 131

14.5 Records and Documentation 132

15 Installation 132

15.1 General 132

15.2 Transportation 133

15.3 Removal of Jacket from Transport Barge 135

15.4 Erection 136

15.5 Pile Installation 139

15.6 Superstructure Installation 145

15.7 Grounding of Installation Welding Equipment 145

16 Inspection 146

16.1 General 146

16.2 Scope 147

16.3 Inspection Personnel 147

16.4 Fabrication Inspection 147

16.5 Loadout, Seafastening, and Transportation Inspection 152

16.6 Installation Inspection 153

16.7 Inspection Documentation 154

17 Accidental Loading 155

17.1 General 155

17.2 Assessment Process 156

17.3 Platform Exposure Category 158

17.4 Probability of Occurrence 158

17.5 Risk Assessment 159

17.6 Fire 160

17.7 Blast 160

17.8 Fire and Blast Interaction 160

17.9 Accidental Loading 160

18 Reuse 161

18.1 General 161

18.2 Reuse Considerations 161

19 Minimum and Special Structures 166

19.1 General 166

19.2 Design Loads and Analysis 167

19.3 Connections 168

19.4 Material and Welding 169

Annex A (informative) API 2A-WSD, 21st Edition vs 22nd Edition Cross-reference 170

Annex B (informative) Commentary 184

Bibliography 292

Figures 5.1 Procedure for Calculation of Wave Plus Current Forces for Static Analysis 25

5.2 Doppler Shift Due to Steady Current 26

5.3 Regions of Applicability of Stream Function, Stokes V, and Linear Wave Theory (from Atkins, 1990; Modified by API Task Group on Wave Force Commentary) 28 5.4 Shielding Factor for Wave Loads on Conductor Arrays as a Function of Conductor Spacing 30

6.1 Example Conical Transition 69

7.2 In-plane Joint Detailing 77

7.3 Out-of-plane Joint Detailing 78

7.4 Terminology and Geometric Parameters, Simple Tubular Joints 79

7.5 Examples of Chord Length, Lc 83

8.1 Example Tubular Joint S-N Curve for T = 16 mm (5 / 8 in.) 91

10.1 Grouted Pile-to-structure Connection with Shear Keys 108

10.2 Recommended Shear Key Details 109

10.1 Connection Design Limitations 109

14.1 Welded Tubular Connections—Shielded Metal Arc Welding 127

17.1 Assessment Process 157

B.5.1 Measured Current Field at 60 ft Depth Around and Through the Bullwinkle Platform in a Loop Current Event in 1991 189

B.5.2 Comparison of Linear and Nonlinear Stretching of Current Profiles 190

B.5.3 Definition of Surface Roughness Height and Thickness 191

B.5.4 Dependence of Steady Flow Drag Coefficient on Relative Surface Roughness 193

B.5.5 Wake Amplification Factor for Drag Coefficient as a Function of K/Cds 195

B.5.6 Wake Amplification Factor for Drag Coefficient as a Function of K 195

B.5.7 Inertia Coefficient as a Function of K 196

B.5.8 Inertia Coefficient as a Function of K/Cds 196

B.5.9 Shielding Factor for Wave Loads on Conductor Arrays as a Function of Conductor Spacing 198

B.5.10 Example Structure 207

B.5.11 Seismic Load Deformation Curve 209

B.6.1 Elastic Coefficients for Local Buckling of Steel Cylinders Under Axial Compression 213

B.6.2 Comparison of Test Data with Design Equation for Fabricated Steel Cylinders Under Axial Compression 213

B.6.3 Design Equation for Fabricated Steel Cylinders Under Bending 215

B.6.4 Comparison of Test Data with Elastic Design Equations for Local Buckling of Cylinders Under Hydrostatic Pressure (M > 0.825D/t) 217

B.6.5 Comparison of Test Data with Elastic Design Equations for Local Buckling of Cylinders Under Hydrostatic Pressure (M < 0.825D/t) 217

B.6.6 Comparison of Test Data with Design Equations for Ring Buckling and Inelastic Local Buckling of Cylinders Under Hydrostatic Pressure 218

B.6.7 Comparison of Test Data with Interaction Equation for Cylinders Under Combined Axial Tension and Hydrostatic Pressure (Fhc Determined from Tests) 219

B.6.8 Comparison of Interaction Equations for Various Stress Conditions for Cylinders Under Combined Axial Compressive Load and Hydrostatic Pressure 220

B.6.9 Comparison of Test Data with Elastic Interaction Curve for Cylinders Under Combined Axial Compressive Load and Hydrostatic Pressure 221

B.6.10 Comparison of Test Data on Fabricated Cylinders with Elastic Interaction Curve for Cylinders Under Combined Axial Load and Hydrostatic Pressure 221

B.6.11 Comparison of Test Data with Interaction Equations for Cylinders Under Combined Axial Compressive Load and Hydrostatic Pressure (Combination Elastic and Yield-type Failures) 222

B.7.1 Adverse Load Patterns with α up to 3.8 226

B.7.2 Computed α 226

B.7.3 Safety Index Betas, API 2A-WSD, 21st Edition, Supplement 1 231

B.7.4 Safety Index Betas, API 2A-WSD, 21st Edition, Supplement 2 231

B.7.5 Comparison of Strength Factors Qu for Axial Loading 234

B.7.6 Comparison of Strength Factors Qu for IPB and OPB 235

B.7.8 Effect of Chord Axial Load on DT Brace Compression Capacity Comparison of University of

Texas Test Data with Chord Load Factor 238

B.7.9 K-joints Under Balanced Axial Loading—Test and FE vs New and Old API 241

B.7.10 T-joints Under Axial Loading—Test and FE vs New and Old API 242

B.7.11 DT-joints Under Axial Compression—Test and FE vs New and Old API 242

B.7.12 All Joints Under BIPB—Test and FE vs New and Old API 243

B.7.13 All Joints Under BOPB—Test and FE vs New and Old API 243

B.8.1 Selection of Frequencies for Detailed Analyses 251

B.8.2 Geometry Definitions for Efthymiou SCFs 257

B.8.3 Basic Air S-N Curve as Applicable to Profiled Welds, Including Size and Toe Correction to the Data 273

B.8.4 S-N Curve and Data for Seawater with CP 273

B.10.1 Measured Bond Strength vs Cube Compressive Strength 279

B.10.2 Histogram of the Safety Factors—Tests with and Without Shear Key Connections 279

B.10.3 Cumulative Histogram of the Safety Factors—Tests with and Without Shear Key Connections 280

B.10.4 Measured Bond Strength vs Cube Compressive Strength Multiplied by the Height-to-spacing Ratio 280

B.17.1 D/T Ratio vs Reduction in Ultimate Capacity, 1220 mm, 1370 mm, and 1525 mm (48 in., 54 in., and 60 in.) Legs—Straight with L = 18.3 m (60 ft), K = 1.0, and Fy = 240 MPa (35 ksi) 288

B.17.2 D/T Ratio vs Reduction in Ultimate Capacity, 1220 mm, 1370 mm, and 1525 mm (48 in., 54 in., and 60 in.) Legs—Straight with L = 18.3 m (60 ft), K = 1.0, and Fy = 345 MPa (50 ksi) 288

B.17.3 D/T Ratio vs Reduction in Ultimate Capacity, 1220 mm, 1370 mm, and 1525 mm (48 in., 54 in., and 60 in.) Legs—Bent with L = 18.3 m (60 ft), K = 1.0, and Fy = 240 MPa (35 ksi) 289

B.17.4 D/T Ratio vs Reduction in Ultimate Capacity, 1220 mm, 1370 mm, and 1525 mm (48 in., 54 in., and 60 in.) Legs—Bent with L = 18.3 m (60 ft), K = 1.0, and Fy = 345 MPa (50 ksi) 289

Tables 4.1 Exposure Category Matrix 18

5.1 Design Loading Conditions 23

5.2 Approximate Current Blockage Factors for Typical Gulf of Mexico Jacket-type Structures 27

5.3 Values Coherence Spectrum Coefficients α, p, q, r, and Δ 38

5.4 Wind Shape Coefficients 39

5.5 Design Level Criteria and Robustness Analysis 41

5.6 Cr Factors for Steel Jacket of Fixed Offshore Platforms 47

5.7 Offshore Design Reference Wind Speed for Drilling Structures 49

5.8 Design Wind Speeds used for Existing Drilling 50

5.9 Deck Acceleration During Design Hurricanes 50

6.1 Values of K and Cm for Various Member Situations 66

6.2 Safety Factors 68

6.3 Limiting Angle α for Conical Transitions 69

7.1 Examples of Joint Classification 76

7.1 Geometric Parameter Validity Range 79

7.2 Values for Qu 81

7.3 Values for C1, C2, C3 82

7.4 Qu for Grouted Joints 84

8.1 Fatigue Life Safety Factors 88

8.2 Basic Design S-N Curves 90

8.3 Factors on Fatigue Life for Weld Improvement Techniques 92

9.1 Pile Factors of Safety for Different Loading Conditions 96

9.2 Minimum Pile Wall Thickness 102

9.3 Shallow Foundation Safety Factors Against Failure 104

10.2 Guyline Factors of Safety 111

11.1 Structural Steel Plates 114

11.1 Structural Steel Plates (Continued) 115

11.2 Structural Steel Shapes 116

11.3 Structural Steel Pipe 117

11.4 Input Testing Conditions 117

13.1 Impact Testing 123

15.1 Guideline Wall Thickness (in SI Units) 142

15.2 Guideline Wall Thickness (in USC Units) 143

16.1 Recommended Minimum Extent of NDE Inspection 150

17.1 Platform Risk Matrix 158

18.1 Recommended Extent of NDE Inspection-Reused Structure 164

A.1 API 2A-WSD, 21st Edition vs 22nd Edition Cross-reference of Figures 170

A.2 API 2A-WSD, 21st Edition vs 22nd Edition Cross-reference of Tables 175

A.3 API 2A-WSD, 21st Edition vs 22nd Edition Cross-reference of Equations 178

B.7.1 Mean Bias Factors and Coefficients of Variation for K-joints 240

B.7.2 Mean Bias Factors and Coefficients of Variation for Y-joints 240

B.7.3 Mean Bias Factors and Coefficients of Variation for X-joints 241

B.8.1 Equations for SCFs in T/Y-joints 260

B.8.2 Equations for SCFs in X-joints 261

B.8.3 Equations for SCFs in Gap/Overlap K-joints 262

B.8.4 Equations for SCFs in KT-joints 263

B.8.5 Expressions for Lmp 265

B.13.1 Average Heat Affected Zone (HAZ) Values 283

B.17.1 Required Tubular Thickness to Locally Absorb Vessel Impact 287

This publication serves as a guide for those who are concerned with the design and construction of new fixed offshoreplatforms and for the relocation of existing platforms used for the drilling, development, production, and storage ofhydrocarbons in offshore areas

In addition, these guidelines are used in conjunction with API 2SIM for the assessment of existing platforms in theevent that it becomes necessary to make a determination of the “fitness for purpose” of the structure

This recommended practice is organized around the framework of the API 2A-WSD, 21st Edition, with the followingsections:

— Section 1: Scope;

— Section 2: Normative References;

— Section 3: Terms, Definitions, Acronyms, and Abbreviations;

— Section 4: Planning (API 2A-WSD, 21st Edition, Section 1);

— Section 5: Design Criteria and Procedures (API 2A-WSD, 21st Edition, Section 2);

— Section 6: Structural Steel Design (API 2A-WSD, 21st Edition, Section 3);

— Section 7: Strength of Tubular Joints (API 2A-WSD, 21st Edition, Section 4);

— Section 8: Fatigue (API 2A-WSD, 21st Edition, Section 5);

— Section 9: Foundation Design (API 2A-WSD, 21st Edition, Section 6);

— Section 10: Other Structural Components and Systems (API 2A-WSD, 21st Edition, Section 7);

— Section 11: Material (API 2A-WSD, 21st Edition, Section 8);

— Section 12: Drawings and Specifications (API 2A-WSD, 21st Edition, Section 9);

— Section 13: Welding (API 2A-WSD, 21st Edition, Section 10);

— Section 14: Fabrication (API 2A-WSD, 21st Edition, Section 11);

— Section 15: Installation (API 2A-WSD, 21st Edition, Section 12);

— Section 16: Inspection (API 2A-WSD, 21st Edition, Section 13);

— Section 17: Accidental Loading (API 2A-WSD, 21st Edition, Section 18);

— Section 18: Reuse (API 2A-WSD, 21st Edition, Section 15);

— Section 19: Minimum and Special Structures (API 2A-WSD, 21st Edition, Section 16);

— Annex A: Listing of figures, tables, and equations;

— Annex B: Commentary;

— Bibliography

— API 2A-WSD, 21st Edition, Section 14 (Surveys) and Section 17 (Assessment of Existing Platforms) have beenremoved in their entirety and now reside in API 2SIM;

— with the publication of API 2FB, the new Section 17 contains only the accidental loading portion of API 2A-WSD,21st Edition, Section 18;

— Annex A provides a listing of API 2A-WSD, 21st Edition tables, figures, and equations with corresponding22nd Edition numbers;

— Annex B contains any commentary for the sections;

— Bibliography contains references for all sections

Planning, Designing, and Constructing Fixed Offshore Platforms—

Working Stress Design

NOTE 5 Specific guidance for fire and blast loading, previously provided in the 2A-WSD, 21st Edition, Section 18,

is now provided in API 2FB [3]

NOTE 6 Specific guidance for marine operations, supplementing the guidance provided in this document, is now provided in API 2MOP [6] The provisions in API 2A-WSD shall govern if there are any conflicts

The following referenced documents are indispensable for the application of this document For dated references, only the edition cited applies For undated references, the latest edition of the referenced document applies (including any addenda/errata)

API Specification 2B, Fabrication of Structural Steel Pipe

API Specification 2C, Specification for Offshore Pedestal-mounted Cranes

API Recommended Practice 2EQ, Seismic Design Procedures and Criteria for Offshore Structures

API Recommended Practice 2GEO, Geotechnical and Foundation Design Considerations

API Recommended Practice 2MET, Derivation of Metocean Design and Operation Conditions

API Recommended Practice 2N, Planning, Designing, and Constructing Structures and Pipelines for

Arctic Conditions

API Recommended Practice 2SIM, Structural Integrity Management of Fixed Offshore Structures

API Bulletin 2TD, Guidelines for Tie-downs on Offshore Production Facilities for Hurricane Season

API Bulletin 2U, Stability Design of Cylindrical Shells

API Specification 4F, Drilling and Well Servicing Structures

AISC 335-89 1, Specification for Structural Steel Buildings—Allowable Stress Design and Plastic Design,

1989 (included in AISC Manual of Steel Construction, Allowable Stress Design, Ninth Edition)

AWS D1.1/D1.1M:2010 2, Structural Welding Code—Steel

3 Terms, Definitions, Acronyms, and Abbreviations

For the purposes of this document, the terms, definitions, acronyms, and abbreviations apply

3.1 Terms and Definitions

The stress in the immediate vicinity of a structural discontinuity

NOTE Can also be described as the linear trend of shell bending and membrane stress, extrapolated to the actual weld toe, excluding the local notch effects of weld shape

3.1.3

manned platform

A platform that is actually and continuously occupied by persons accommodated and living thereon

3.1.4

mean zero-crossing period

The average time between successive crossings with a positive slope (up crossings) of the zero axis in a time history of water surface, stress, etc

3.1.7

random waves

A representation of the irregular surface elevations and associated water particle kinematics of the marine

environment

NOTE Random waves can be represented analytically by a summation of sinusoidal waves of different heights,

periods, phases, and directions For fatigue strength testing, a sequence of sinusoidal stress cycles of random

amplitude may be used [253]

significant wave height

The average height of the highest one-third of all the individual waves present in a sea state

NOTE In random seas, the corresponding significant stress range is more consistent with S-N curves than the often

misused RMS variance

3.1.11

S-N curve

A representation of empirically determined relationships between stress range and number of cycles to

failure, including the effects of weld profile and discontinuities at the weld toe

3.1.12

steady state

The response of a structure to waves when the transient effects caused by the assumed initial conditions

have become insignificant due to damping

3.1.13

stress concentration factor

SCF

The SCF for a particular stress component and location on a tubular connection is the ratio of the HSS to

the nominal stress at the cross section containing the hot spot

3.2 Acronyms and Abbreviations

CAFL constant amplitude fatigue limit COV coefficient of variation

CTOD crack tip opening displacement

GMAW gas metal arc welding

HSSR hot spot stress range

JIP joint industry project LRFD load and resistance factor design

MT magnetic particle inspection technique

OTJTC Offshore Tubular Joint Technical Committee

PT liquid penetrant inspection technique PWHT postweld heat treatment

RT radiographic inspection technique SCF stress concentration factor SSSV subsurface safety valves

UT ultrasonic inspection technique

4 Planning

4.1 General

4.1.1 Planning

This publication serves as a guide for those who are concerned with the design and construction of new

platforms and for the relocation of existing platforms used for the drilling, development, and storage of

hydrocarbons in offshore areas

In addition, these guidelines shall be used in conjunction with API 2SIM for the assessment of existing

platforms in the event that it becomes necessary to make a determination of the fitness-for-purpose of the

structure

Adequate planning should be done before actual design is started in order to obtain a workable and

economical offshore structure to perform a given function The initial planning should include the

determination of all criteria upon which the design of the platform is based

4.1.2 Design Criteria

Design criteria as used herein include all operational requirements and environmental data that could

affect the detailed design of the platform

4.1.3 Codes and Standards

This publication has also incorporated and made maximum use of existing codes and standards that have

been found acceptable for engineering design and practices from the standpoint of public safety

4.2 Operational Considerations

4.2.1 Function

The function for which a platform is designed is usually categorized as drilling, producing, storage,

materials handling, living quarters, or a combination of these The platform configuration should be

determined by a study of layouts of equipment to be located on the decks Careful consideration should

be given to the clearances and spacing of equipment before the final dimensions are decided upon

4.2.2 Location

The location of the platform should be specific before the design is completed Environmental conditions

vary with geographic location; within a given geographic area, the foundation conditions generally vary as

do such parameters as design wave heights, periods, and tides

4.2.3 Orientation

The orientation of the platform refers to its position in the plan referenced to a fixed direction such as true

north Orientation is usually governed by the direction of prevailing seas, winds, currents, and operational

requirements

4.2.4 Water Depth

Information on water depth and tides is needed to select appropriate oceanographic design parameters The water depth should be determined as accurately as possible so that elevations can be established for boat landings, fenders, decks, and corrosion protection

4.2.5 Access and Auxiliary Systems

The location and number of stairways and access boat landings on the platform should be governed by safety considerations A minimum of two accesses to each manned level should be installed and should

be located so that escape is possible under varying conditions Operating requirements should also be considered in stairway locations

4.2.6 Fire Protection

The safety of personnel and possible destruction of equipment requires attention to fire protection methods The selection of the system depends upon the function of the platform Procedures should conform to all federal, state, and local regulations where they exist

4.2.7 Deck Elevation

Large forces and overturning moments result when waves strike a platform’s lower deck and equipment Unless the platform has been designed to resist these forces, the elevation of the deck should be established to provide adequate clearance above the design maximum crest elevation Consideration should be given to providing an “air gap” and an additional allowance for local maximum crest elevations, which are higher than the design maximum crest elevation The deck elevation shall be determined in accordance with 5.3.4.3 and API 2MET

4.2.8 Wells

Exposed well conductors add environmental forces to a platform and require support Their number, size, and spacing should be known early in the planning stage Conductor pipes may or may not assist in resisting the wave force If the platform is to be set over an existing well with the wellhead above water, information is needed on the dimensions of the tree, size of conductor pipe, and the elevations of the casing head flange and top of wellhead above mean low water If the existing well is a temporary subsea completion, plans should be made for locating the well and setting the platform properly so that the well can later be extended above the surface of the water Planning should consider the need for future wells

4.2.9 Equipment and Material Layouts

Layouts and weights of drilling equipment and material and production equipment are needed in the development of the design Heavy concentrated loads on the platform should be located so that proper framing for supporting these loads can be planned When possible, consideration should be given to future operations

4.2.10 Personnel and Material Handling

Plans for handling personnel and materials should be developed at the start of the platform design, along with the type and size of supply vessels and the anchorage system required to hold them in position at the platform The number, size, and location of the boat landings should be determined as well

The type, capacity, number, and location of the deck cranes should also be determined If equipment or

materials are to be placed on a lower deck, then adequately sized and conveniently located hatches

should be provided on the upper decks as appropriate for operational requirements The possible use of

helicopters should be established and facilities provided for their use

4.2.11 Spillage and Contamination

Provision for handling spills and potential contaminants should be provided A deck drainage system that

collects and stores liquids for subsequent handling should be provided The drainage and collection

system should meet appropriate governmental regulations

4.2.12 Exposure

Design of all systems and components should anticipate extremes in environmental phenomena that may

be experienced at the site

4.3 Environmental Considerations

4.3.1 General Meteorological and Oceanographic Considerations

Experienced specialists should be consulted when defining the pertinent meteorological and

oceanographic conditions affecting a platform site The following sections present a general summary of

the information that could be required Selection of information needed at a site should be made after

consultation with both the platform designer and a meteorological-oceanographic specialist Measured

and/or model-generated data should be statistically analyzed to develop the descriptions of normal and

extreme environmental conditions as follows

a) Normal environmental conditions (conditions that are expected to occur frequently during the life of

the structure) are important both during the construction and the service life of a platform

b) Extreme conditions (conditions that occur quite rarely during the life of the structure) are important in

formulating platform design loadings

All data used should be carefully documented The estimated reliability and the source of all data should

be noted, and the methods employed in developing available data into the desired environmental values

should be defined

4.3.2 Winds

Wind forces are exerted upon that portion of the structure that is above the water, as well as on any

equipment, deck houses, and derricks that are located on the platform The wind speed may be classified as:

— gusts that average less than 1 min in duration, and

— sustained wind speeds that average 1 min or longer in duration

Wind data should be adjusted to a standard elevation, such as 10 m (33 ft) above mean water level, with

a specified averaging time, such as 1 hour Wind data may be adjusted to any specified averaging time or

elevation using standard profiles and gust factors (see 5.3.2)

The spectrum of wind speed fluctuations about the average should be specified in some instances For example, compliant structures like compliant towers and tension leg platforms in deep water may have natural sway periods in the range of 1 min., in which there is significant energy in the wind speed fluctuations

The following should be considered in determining appropriate design wind speeds

For normal conditions:

— the frequency of occurrence of specified sustained wind speeds from various directions for each month or season,

— the persistence of sustained wind speeds above specified thresholds for each month or season,

— the probable speed of gusts associated with sustained wind speeds

For extreme conditions:

— projected extreme wind speeds of specified directions and averaging times as a function of their recurrence interval should be developed Data should be given concerning the following:

— the measurement site, date of occurrence, magnitude of measured gusts and sustained wind speeds, and wind directions for the recorded wind data used during the development of the projected extreme winds;

— the projected number of occasions during the specified life of the structure when sustained wind speeds from specified directions should exceed a specific lower bound wind speed

4.3.3 Waves

Wind-driven waves are a major source of environmental forces on offshore platforms Such waves are irregular in shape, vary in height and length, and may approach a platform from one or more directions simultaneously For these reasons, the intensity and distribution of the forces applied by waves are difficult to determine Because of the complex nature of the technical factors to be considered in developing wave-dependent criteria for the design of platforms, experienced specialists knowledgeable in the fields of meteorology, oceanography, and hydrodynamics should be consulted

In those areas where prior knowledge of oceanographic conditions is insufficient, the development of wave-dependent design parameters shall include at least the following steps

— Development of all necessary meteorological data

— Projection of surface wind fields

— Prediction of deepwater general seastates along storm tracks using an analytical model

— Definition of maximum possible seastates consistent with geographical limitations

— Delineation of bathymetric effects on seastates

— Introduction of probabilistic techniques to predict seastate occurrences at the platform site against

various time bases

— Development of design wave parameters through physical and economic risk evaluation

In areas where considerable previous knowledge and experience with oceanographic conditions exist, the

foregoing sequence may be shortened to those steps needed to project this past knowledge into the

required design parameters

It is the responsibility of the platform owner to select the design seastate, after considering all of the

factors listed in 4.5 In developing seastate data, consideration should be given to the following

For normal conditions (for both wind seas and swell):

— for each month and/or season, the probability of occurrence and average persistence of various sea

states [e.g waves higher than 3 m (10 ft)] from specified directions in terms of general seastate description parameters (e.g the significant wave height and the average wave period);

— the wind speeds, tides, and currents occurring simultaneously with the above seastates

For extreme conditions:

— definition of the extreme seastates should provide an insight as to the number, height, and crest

elevations of all waves above a certain height that might approach the platform site from any direction during the entire life of the structure Projected extreme wave heights from specified directions should

be developed and presented as a function of their expected average recurrence intervals Other data that should be developed include:

— the probable range and distribution of wave periods associated with extreme wave heights;

— the projected distribution of other wave heights, maximum crest elevations, and the wave energy

spectrum in the sea state producing an extreme wave height(s);

— the tides, currents, and winds likely to occur simultaneously with the seastate producing the extreme

waves;

— the nature, date, and place of the events that produced the historical seastates, for example,

Hurricane Camille, August 1969, U.S Gulf of Mexico was used in the development of the projected values

4.3.4 Tides

Tides are important considerations in platform design Tides may be classified as:

a) astronomical tide,

b) wind tide, and

c) pressure differential tide

The latter two are frequently combined and called storm surge; the sum of the three tides is called the storm tide In the design of a fixed platform, the storm tide elevation is the datum upon which storm waves are superimposed The variations in elevations of the daily astronomical tides, however, determine the elevations of the boat landings, barge fenders, the splash zone treatment of the steel members of the structure, and the upper limits of marine growth

4.3.5 Currents

Currents are important in the design of fixed platforms They affect:

— the location and orientation of boat landings and barge bumpers, and

— the forces on the platform

Where possible, boat landings and barge bumpers should be located to allow the boat to engage the platform as it moves against the current

The most common categories of currents are:

a) tidal currents (associated with astronomical tides),

b) circulatory currents (associated with oceanic-scale circulation patterns), and

c) storm-generated currents

The vector sum of these three currents is the total current, and the speed and direction of the current at specified elevations is the current profile The total current profile associated with the sea state producing the extreme waves should be specified for platform design The frequency of occurrence of total current speed and direction at different depths for each month and/or season may be useful for planning operations

4.3.6 Ice

In some areas where petroleum development is being carried out, subfreezing temperatures can prevail a major portion of the year, causing the formation of sea ice Sea ice may exist in these areas as first-year sheet ice, multiyear floes, first-year and multiyear pressure ridges, and/or ice islands Loads produced by ice features could constitute a dominant design factor for offshore platforms in the most severe ice areas such as the Alaskan Beaufort and Chukchi Seas, and Norton Sound In milder climates, such as the southern Bering Sea and Cook Inlet, the governing design factor may be seismic or wave induced, but ice features would nonetheless influence the design and construction of the platforms considered

Research in ice mechanics is being conducted by individual companies and joint industry groups to develop design criteria for arctic and subarctic offshore areas Global ice forces vary depending on such factors as size and configuration of platform, location of platform, mode of ice failure, and unit ice strength Unit ice strength depends on the ice feature, temperature, salinity, speed of load application, and ice composition Forces to be used in design should be determined in consultation with qualified experts

API 2N outlines conditions that shall be addressed in the design and construction of structures in arctic and subarctic offshore regions

4.3.7 Active Geologic Processes

4.3.7.1 General

In many offshore areas, geologic processes associated with movement of the near-surface sediments

occur within time periods that are relevant to fixed platform design The nature, magnitude, and return

intervals of potential seafloor movements should be evaluated by site investigations and judicious

analytical modeling to provide input for determination of the resulting effects on structures and

foundations Because of uncertainties with definition of these processes, a parametric approach to

studies may be helpful in the development of design criteria

4.3.7.2 Earthquakes

Seismic forces should be considered in platform design for areas that are determined to be seismically

active Areas are considered seismically active on the basis of previous records of earthquake activity,

both in frequency of occurrence and in magnitude Seismic activity of an area for purposes of design of

offshore structures is rated in terms of possible severity of damage to these structures The seismic maps

for U.S coastal waters contained in API 2EQ shall be used if no detailed investigation regarding the

seismicity of an area has been performed

4.3.7.3 Faults

In some offshore areas, fault planes may extend to the seafloor with the potential for either vertical or

horizontal movement Fault movement can occur as a result of seismic activity, removal of fluids from

deep reservoirs, or long-term creep related to large-scale sedimentation or erosion Siting of facilities in

close proximity to fault planes intersecting the seafloor should be avoided if possible If circumstances

dictate siting structures near potentially active features, the magnitude and time scale of expected

movement should be estimated on the basis of geologic study for use in the platform design

4.3.7.4 Seafloor Instability

Movement of the seafloor can occur as a result of loads imposed on the soil mass by ocean wave

pressures, earthquakes, soil self-weight, or combination of these phenomena Weak, under-consolidated

sediments occurring in areas where wave pressures are significant at the seafloor are most susceptible to

wave-induced movement and may be unstable under negligible slope angles Earthquake-induced forces

can induce failure of seafloor slopes that are otherwise stable under the existing self-weight forces and

wave conditions

In areas of rapid sedimentation, such as actively growing deltas, low soil strength, soil self-weight, and

wave-induced pressures are believed to be the controlling factors for the geologic processes that

continually move sediment downslope Important platform design considerations under these conditions

include the effects of large-scale movement of sediment in areas subjected to strong wave pressures,

downslope creep movements in areas not directly affected by wave-seafloor interaction, and the effects of

sediment erosion and/or deposition on platform performance

The scope of site investigations in areas of potential instability should focus on identification of metastable

geologic features surrounding the site and definition of the soil engineering properties required for

modeling and estimating seafloor movements

Analytical estimates of soil movement as a function of depth below the mudline can be used with soil engineering properties to establish expected forces on platform members Geologic studies employing historical bathymetric data may be useful for quantifying deposition rates during the design life of the facility

4.3.7.5 Scour

Scour is removal of seafloor soils caused by currents and waves Such erosion can be a natural geologic process or can be caused by structural elements interrupting the natural flow regime near the seafloor From observation, scour can usually be characterized as some combination of the following

a) Local scour—steep-sided scour pits around such structure elements as piles and pile groups, generally as seen in flume models

b) Global scour—shallow scoured basins of large extent around a structure, possibly due to overall structure effects, multiple structure interaction, or wave/soil/structure interaction

c) Overall seabed movement—movement of sandwaves, ridges, and shoals that would occur in the absence of a structure This movement can be caused by lowering or accumulation

The presence of mobile seabed sandwaves, sandhills, and sand ribbons indicates a vigorous natural scour regime Past bed movement may be evidenced by geophysical contrasts or by variation in density, grading, color, or biological indicators in seabed samples and soundings Sand or silt soils in water depths less than about 40 m (130 ft) are particularly susceptible to scour, but scour has been observed in cobbles, gravels, and clays; in deeper water, the presence of scour depends on the vigor of currents and waves

Scour can result in removal of vertical and lateral support for foundations, causing undesirable settlements of mat foundations and overstressing of foundation elements Where scour is a possibility, it should be accounted for in design and/or its mitigation should be considered Offshore scour phenomena are described in References [36] and [37]

4.3.7.6 Shallow Gas

The presence of either biogenic or petrogenic gas in the pore water of near-mudline soils is an engineering consideration in offshore areas In addition to being a potential drilling hazard for both site investigation soil borings and oil well drilling, the effects of shallow gas may be important to engineering

of the foundation The importance of assumptions regarding shallow gas effects on interpreted soil engineering properties and analytical models of geologic processes should be established during initial stages of the design

4.3.7.7 Marine Growth

Offshore structures accumulate marine growth to some degree in all the world’s oceans Marine growth is generally greatest near the mean water level but in some areas may be significant 60 m (200 ft) or more below the mean water level Marine growth increases wave forces (by increasing member diameter and surface roughness) and mass of the structure and should be considered in design

4.3.7.8 Tsunamis

Platforms in shallow water that may be subjected to tsunamis shall be investigated for the effects of the resulting forces

4.3.7.9 Other Environmental Information

Depending on the platform site, other environmental information of importance includes records and/or

predictions with respect to precipitation, fog, wind chill, air temperatures, and sea temperatures General

information on the various types of storms that might affect the platform site should be used to

supplement other data developed for normal conditions Statistics can be compiled giving the expected

occurrence of storms by season, direction of approach, etc Of special interest for construction planning

are the duration, the speed of movement and development, and the extent of these conditions Also of

major importance is the ability to forecast storms in the vicinity of a platform

4.4 Site Investigation—Foundations

4.4.1 Site Investigation Objectives

Knowledge of the soil conditions existing at the site of construction on any sizable structure is necessary

to permit a safe and economical design On-site soil investigations should be performed to define the

various soil strata and their corresponding physical and engineering properties Previous site

investigations and experience at the site may permit the installation of additional structures without

additional studies

The initial step for a site investigation is reconnaissance Information may be collected through a review

of available geophysical data and soil boring data available in engineering files, literature, or government

files The purpose of this review is to identify potential problems and to aid in planning subsequent data

acquisition phases of the site investigation

Soundings and any required geophysical surveys should be part of the on-site studies and generally

should be performed before borings These data should be combined with an understanding of the

shallow geology of the region to develop the required foundation design parameters The on-site studies

should extend throughout the depth and areal extent of soils that will affect or be affected by installation of

the foundation elements

4.4.2 Seabottom Surveys

The primary purpose of a geophysical survey in the vicinity of the site is to provide data for a geologic

assessment of foundation soils and the surrounding area that could affect the site Geophysical data

provide evidence of slumps, scarps, irregular or rough topography, mud volcanoes, mud lumps, collapse

features, sand waves, slides, faults, diapirs, erosional surfaces, gas bubbles in the sediments, gas seeps,

buried channels, and lateral variations in strata thicknesses The areal extent of shallow soil layers may

sometimes be mapped if good correspondence can be established between the soil boring information

and the results from the seabottom surveys

The geophysical equipment used includes the following:

a) sub-bottom profiler (tuned transducer) for definition of bathymetry and structural features within the

near-surface sediments;

b) side-scan sonar to define surface features;

c) boomer or minisparker for definition of structure to depths past a hundred meters (few hundred feet)

below the seafloor;

d) sparker, air gun, water gun, or sleeve exploder for definition of structure at deeper depths and to tie together with deep seismic data from reservoir studies

Shallow sampling of near-surface sediments using drop, piston, grab samplers, or vibrocoring along geophysical track lines may be useful for calibration of results and improved definition of the shallow geology

See Reference [38] for a more detailed description of commonly used seabottom survey systems

4.4.3 Soil Investigation and Testing

If practical, the soil sampling and testing program should be defined after a review of the geophysical results On-site soil investigation should include one or more soil borings to provide samples suitable for engineering property testing and a means to perform in situ testing, if required The number and depth of borings depend on the soil variability in the vicinity of the site and the platform configuration Likewise, the degree of sophistication of soil sampling and preservation techniques, required laboratory testing, and the need for in situ property testing are a function of the platform design requirements and the adopted design philosophy

As a minimum requirement, the foundation investigation for pile-supported structures should provide the soil engineering property data needed to determine the following parameters:

a) axial capacity of piles in tension and compression,

b) load-deflection characteristics of axially and laterally loaded piles,

c) pile driveability characteristics,

d) mudmat bearing capacity

The required scope of the soil sampling, in situ testing, and laboratory testing programs is a function of the platform design requirements and the need to characterize active geologic processes that may affect the facility For novel platform concepts, deepwater applications, platforms in areas of potential slope instability, and gravity-base structures, the geotechnical program should be tailored to provide the data necessary for pertinent soil-structure interaction and pile capacity analyses

When performing site investigations in frontier areas or areas known to contain carbonate material, the investigation should include diagnostic methods to determine the existence of carbonate soils Typically, carbonate deposits are variably cemented and range from lightly cemented with sometimes significant void spaces to extremely well-cemented In planning a site investigation program, there should be enough flexibility in the program to switch between soil sampling, rotary coring, and in situ testing as appropriate Qualitative tests should be performed to establish the carbonate content In a soil profile that contains carbonate material (usually in excess of 15 % to 20 % of the soil fraction) engineering behavior of the soil could be adversely affected In these soils additional field and laboratory testing and engineering may be warranted

4.5 Selecting the Design Environmental Conditions

Selection of the environmental conditions to which platforms are designed shall be the responsibility of the owner The design environmental criteria should be developed from the environmental information

described in 4.3, and may also include a risk analysis where prior experience is limited The risk analysis

may include the following:

— historical experience;

— the planned life and intended use of the platform;

— the possible loss of human life;

— the financial loss due to platform damage or loss including lost production, cleanup, replacing the

platform and redrilling wells, etc

As a guide, the recurrence interval for oceanographic design criteria should be several times the planned

life of the platform Experience with major platforms in the U.S Gulf of Mexico supports the use of

100-year oceanographic design criteria This is applicable only to new and relocated platforms that are

manned during the design event or that are structures where the loss of or severe damage to the

structure could result in a high consequence of failure Consideration may be given to reduced design

requirements for the design or relocation of other structures that are unmanned or evacuated during the

design event and have either a shorter design life than the typical 20 years or where the loss of or severe

damage to the structure would not result in a high consequence of failure Guidelines to assist in the

establishment of the exposure category to be used in the selection of criteria for the design of new

platforms are provided in 4.7 Risk analyses may justify either longer or shorter recurrence intervals for

design criteria However, not less than 100-year oceanographic design criteria shall be considered where

the design event may occur without warning while the platform is manned and/or when there are

restrictions on the speed of personnel removal (e.g great flying distances)

Section 5 provides guidelines for developing oceanographic design criteria that are appropriate for use

with the exposure category levels defined in 4.7 For all new Category L-1 structures located in U.S

waters, the use of nominal 100-year return period is recommended For all new Category L-2 and L-3

structures located in the U.S Gulf of Mexico north of 27 °N latitude and west of 86 °W longitude,

guidelines for using shorter return criteria are provided

Where sufficient information is available, the designer may take into account the variation in

environmental conditions expected to occur from different directions When this is considered, an

adequate tolerance in platform orientation should be used in the design of the platform and measures

shall be employed during installation to ensure the platform is positioned within the allowed tolerance

Structures should be designed for the combination of wind, wave, and current conditions causing the

extreme load, accounting for their joint probability of occurrence (both magnitude and direction) For most

template, tower, gravity, and caisson types of platforms, the design fluid dynamic load is predominantly

due to waves, with currents and winds playing a secondary role The design conditions, therefore, consist

of the wave conditions and the currents and winds likely to coexist with the design waves For compliant

structures, response to waves is reduced so that winds and currents become relatively more important Also, for structures in shallow water and structures with a large deck and/or superstructure, the wind load may be a more significant portion of the total environmental force This may lead to multiple sets of design conditions including, as an example, for Level L-1 structures:

— the 100-year waves with associated winds and currents, and

— the 100-year winds with associated waves and currents

Two levels of earthquake environmental conditions are needed to address the risk of damage or structure collapse These are:

a) ground motion, which has a reasonable likelihood of not being exceeded at the site during the platform life; and

b) ground motion for a rare, intense earthquake

Consideration of the foregoing factors has led to the establishment of the hydrodynamic force guidelines

of 5.3.4 and the guidelines for earthquake design of 5.3.6

4.6 Platform Types

4.6.1 Fixed Platforms

4.6.1.1 General

A fixed platform is defined as a platform extending above the water surface and supported at the seabed

by means of piling, spread footing(s), or other means with the intended purpose of remaining stationary over an extended period

4.6.1.2 Jackets or Templates

These type platforms generally consist of the following:

— completely braced, redundant welded tubular space frame extending from an elevation at or near the sea bed to above the water surface, which is designed to serve as the main structural element of the platform, transmitting lateral and vertical forces to the foundation;

— piles or other foundation elements that permanently anchor the platform to the ocean floor and carry both lateral and vertical loads;

— a superstructure providing deck space for supporting operational and other loads

4.6.1.3 Towers

A tower platform is a modification of the jacket platform that has relatively few large diameter [e.g 5 m (15 ft)] legs Some towers may be floated to location and placed in position by selective flooding Tower platforms may or may not be supported by piling Where piles are used, they are driven through sleeves inside or attached to the outside of the legs The piling may also serve as well conductors If the tower’s support is furnished by spread footings instead of by piling, the well conductors may be installed either inside or outside the legs

4.6.1.4 Gravity Structures

A gravity structure is one that relies on the weight of the structure rather than piling to resist

environmental loads

4.6.1.5 Minimum Nonjacket and Special Structures

Many structures have been installed and are serving satisfactorily that do not meet the definition for jacket

type platforms as defined above In general, these structures do not have reserve strength or redundancy

equal to conventional jacket type structures For this reason, special recommendations regarding design

and installation are provided in Section 19 Minimum structures are defined as structures that have one or

more of the following attributes:

a) structural framing that provides less reserve strength and redundancy than a typical well-braced,

three-leg template type platform;

b) freestanding and guyed caisson platforms that consist of one large tubular member supporting one or

more wells;

c) well conductor(s) or freestanding caisson(s), which are utilized as structural and/or axial foundation

elements by means of attachment using welded, nonwelded, or nonconventional welded connections;

d) threaded, pinned, or clamped connections to foundation elements (piles or pile sleeves);

e) braced caissons and other structures where a single element structural system is a major component

of the platform, such as a deck supported by a single deck leg or caisson

4.6.1.6 Compliant Towers

A compliant tower is a bottom-founded structure having substantial flexibility It is flexible enough that

applied dynamic forces are resisted in significant part by inertial forces The result is a reduction in forces

transmitted to the supporting foundation Guyed towers are included in this category as they are normally

compliant, unless the guying system is very stiff Compliant towers are covered in this document only to

the extent that the provisions are applicable

4.6.2 Floating Production Systems

A number of different floating structures are being developed and used as floating production systems

(e.g tension leg platforms, spars, semisubmersibles) Many aspects of this document are applicable to

certain aspects of the design of these structures API 2FPS [4] provides general guidance for floating

production systems while API 2T [7] provides specific advice for TLPs

4.6.3 Related Structures

Other structures include underwater oil storage tanks, bridges connecting platforms, flare booms, drilling

derricks, etc Specific advice regarding tie-downs for these types of structures is provided in API 2TD

4.7 Exposure Categories

4.7.1 General

Structures can be categorized by various levels of exposure to determine criteria for the design of new platforms and the assessment of existing platforms that are appropriate for the intended service of the structure

The levels are determined by consideration of life safety and consequences of failure Life safety considers the maximum anticipated environmental event that would be expected to occur while personnel are on the platform Consequences of failure should consider the factors listed in 4.5 and discussed in B.4.7 Such factors include anticipated losses to the owner (platform and equipment repair or replacement, lost production, cleanup), anticipated losses to other operators (lost production through trunklines), and anticipated losses to industry and government

Categories for life safety are as follows:

— S-1 is manned-nonevacuated,

— S-2 is manned-evacuated,

— S-3 is unmanned

Categories for consequences of failure are as follows:

— C-1 is high consequence of failure,

— C-2 is medium consequence of failure,

— C-3 is low consequence of failure

The level to be used for platform categorization is the more restrictive level for either life safety or consequence of failure Platform categorization may be revised over the life of the structure as a result of changes in factors affecting life safety or consequence of failure

The exposure category should be determined using the matrix provided in Table 4.1

Table 4.1—Exposure Category Matrix Life Safety Category

Consequence Category C-1, High

Consequence

C-2, Medium Consequence

C-3, Low Consequence

S-1 manned-nonevacuated L-1 a L-1 a L-1 a S-2 manned-evacuated L-1 L-2 L-2

a Manned-nonevacuated platforms are presently not applicable to the U.S GoM waters where platforms are normally evacuated ahead of hurricane events The metocean design criteria in Section 5 have not been verified as adequate for manned-nonevacuated in the U.S GoM However, the winter storm, sudden hurricane, and earthquake criteria for the U.S GoM have been verified as adequate for the manned-nonevacuated situation occurring during those events when platforms in the U.S GoM waters are not normally evacuated

The manned-nonevacuated category refers to a platform that is continuously (or nearly continuously)

occupied by persons accommodated and living thereon and from which personnel evacuation prior to the

design environmental event is either not intended or impractical A platform shall be categorized as S-1

manned-nonevacuated unless the particular requirements for S-2 or S-3 apply throughout the design

service life of the platform

4.7.2.3 S-2, Manned-evacuated

The manned-evacuated category refers to a platform that is normally manned except during a forecast

design environmental event For categorization purposes, a platform shall not be categorized as a

manned-evacuated platform unless all of the following apply:

a) reliable forecast of a design environmental event is technically and operationally feasible, and the

weather between any such forecast and the occurrence of the design environmental event is not likely to inhibit an evacuation;

b) prior to a design environmental event, evacuation is planned;

c) sufficient time and resources exist to safely evacuate all personnel from the platform and all other

platforms likely to require evacuation for the same storm

4.7.2.4 S-3, Unmanned

The unmanned category refers to a platform that is not normally manned or a platform that is not

classified as either manned-nonevacuated or manned-evacuated Platforms in this classification may

include emergency shelters However, platforms with permanent quarters are defined as manned and

should be classified as manned-nonevacuated or as manned-evacuated as defined above An

occasionally manned platform may be categorized as unmanned only in certain conditions (see

B.4.7.2.4)

4.7.3 Consequence of Failure

4.7.3.1 General

As stated in 4.7.1, consequences of failure should include consideration of anticipated losses to the

owner, the other operators, and the industry in general The following descriptions of relevant factors

serve as a basis for determining the appropriate level for consequence of failure

4.7.3.2 C-1 High Consequence

The high consequence of failure category refers to major platforms and/or those platforms that have the

potential for well flow of either oil or sour gas in the event of platform failure In addition, it includes

platforms where the shut-in of the oil or sour gas production is not planned or not practical prior to the

occurrence of the design event (such as areas with high seismic activity) Platforms that support major oil transport lines [see B.4.7.3 c)] and/or storage facilities for intermittent oil shipment are also considered to

be in the high consequence category All new U.S Gulf of Mexico platforms that are designed for installation in water depths greater than 122 m (400 ft) are included in this category unless a lower consequence of failure can be demonstrated to justify a reduced classification

4.7.3.3 C-2 Medium Consequence

The medium consequence of failure category refers to platforms where production would be shut-in during the design event All wells that could flow on their own in the event of platform failure shall contain fully functional, subsurface safety valves, which are manufactured and tested in accordance with the applicable API specifications Oil storage is limited to process inventory and “surge” tanks for pipeline transfer

4.7.3.4 C-3 Low Consequence

The low consequence of failure category refers to minimal platforms where production would be shut-in during the design event All wells that could flow on their own in the event of platform failure shall contain fully functional, subsurface safety valves, which are manufactured and tested in accordance with applicable API specifications These platforms may support production departing from the platform and low volume infield pipelines Oil storage is limited to process inventory New U.S Gulf of Mexico platforms

in this category includes caissons or small well protectors with no more than five well completions on or connected to the platform and no more than two conductors at the platform Total deck area (excluding helideck) is limited to 37 m2 (400 ft2) and contains no more than two pieces of production equipment In addition, platforms in this category are defined as structures in water depths not exceeding 30 m (100 ft)

4.8 Platform Reuse

Existing platforms may be removed and relocated for continued use at a new site When relocation is considered, the platform should be inspected to ensure that it is in (or can be returned to) an acceptable condition In addition, it should be reanalyzed and reevaluated for the use, conditions, and loading anticipated at the new site In general, this inspection, reevaluation, and any required repairs or modification should follow the procedures and provisions for new platforms that are stated in this recommended practice Additional special provisions regarding reuse are listed in Section 18

4.9 Platform Assessment

An assessment to determine fitness-for-purpose may be required during the life of a platform This procedure is normally initiated by a change in the platform usage such as revised manning or loading, by modifications to the condition of the platform such as damage or deterioration, or by a reevaluation of the environmental loading or the strength of the foundation General industry practices recognize that older, existing structures may not meet current design standards However, many of these platforms that are in

an acceptable condition can be shown to be structurally adequate using a risk-based assessment criteria that considers platform use, location, and the consequences of failure Guidance on how to assess an existing platform is provided in API 2SIM

4.10 Safety Considerations

The safety of life and property depends upon the ability of the structure to support the loads for which it was designed and to survive the environmental conditions that may occur Over and above this overall

concept, good practice dictates use of certain structural additions, equipment, and operating procedures

on a platform so that injuries to personnel will be minimized and the risk of fire, blast, and accidental

loading (e.g collision from ships, dropped objects) is reduced Governmental regulations listed in 4.11

and all other applicable regulations should be met

4.11 Regulations

Each country has its own set of regulations concerning offshore operations Listed below are some of the

typical rules and regulations that, if applicable, should be considered when designing and installing

offshore platforms in U.S territorial waters Other regulations may also be in effect It is the responsibility

of the operator to determine which rules and regulations are applicable and should be followed,

depending upon the location and type of operations to be conducted

a) 33 Code of Federal Regulations Parts 140 to 147, Outer Continental Shelf Activities, U.S Coast

Guard, Department of Transportation These regulations stipulate requirements for identification marks for platforms, means of escape, guard rails, fire extinguishers, life preservers, ring buoys, first-aid kits, etc

b) 33 Code of Federal Regulations Part 67, Aids to Navigation on Artificial Islands and Fixed Structures,

U.S Coast Guard, Department of Transportation These regulations prescribe in detail the requirements for installation of lights and foghorns on offshore structures in various zones

c) 30 Code of Federal Regulations Part 250, Oil and Gas and Sulphur Operations in the Outer

Continental Shelf. These regulations govern the marking, design, fabrication, installation, operation, and removal of offshore structures and related appurtenances

d) 29 Code of Federal Regulations Part 1910, Occupational Safety and Health Standards These

regulations provide requirements for safe design of floors, handrails, stairways, ladders, etc Some of the requirements may apply to components of offshore structures that are located in state waters

e) 33 Code of Federal Regulations Part 330, Nationwide Permit Program, U.S Corps of Engineers This

document describes requirements for making application for permits for work (e.g platform installation) in navigable waters Section 10 of the River and Harbor Act of 1899 and Section 404 of the Clean Water Act apply to state waters

f) Obstruction Marking and Lighting, Federal Aviation Administration This booklet sets forth

requirements for marking towers, poles, and similar obstructions Platforms with derricks, antennae, etc are governed by the rules set forth in this booklet Additional guidance is provided by API 2L

g) Various state and local agencies (e.g U.S Department of Wildlife and Fisheries) require notification

of any operations that may take place under their jurisdiction

Other regulations concerning offshore pipelines, facilities, drilling operations, etc may be applicable and

should be consulted

5 Design Criteria and Procedures

b) weight of equipment and appurtenant structures permanently mounted on the platform;

c) hydrostatic forces acting on the structure below the waterline including external pressure and buoyancy

c) the weight of consumable supplies and liquids in storage tanks;

d) the forces exerted on the structure from operations such as drilling, material handling, vessel mooring, and helicopter loadings;

e) the forces exerted on the structure from deck crane usage These forces are derived from consideration of the suspended load and its movement as well as dead load

5.1.2.4 Environmental Loads

Environmental loads are loads imposed on the platform by natural phenomena including wind, current, wave, earthquake, snow, ice, and earth movement Environmental loads also include the variation in hydrostatic pressure and buoyancy on members caused by changes in the water level due to waves and

tides Environmental loads should be anticipated from any direction unless knowledge of specific

conditions makes a different assumption more reasonable

5.1.2.5 Construction Loads

Loads resulting from fabrication, loadout, transportation, and installation should be considered in design

and are further defined in 5.4

5.1.2.6 Removal and Reinstallation Loads

For platforms that are to be relocated to new sites, loads resulting from removal, onloading,

transportation, upgrading, and reinstallation should be considered in addition to the above construction

loads

5.1.2.7 Dynamic Loads

Dynamic loads are the loads imposed on the platform due to response to an excitation of a cyclic nature

or due to reacting to impulsive loads or impact Excitation of a platform may be caused by waves, wind,

earthquake, or machinery Impact may be caused by a barge or boat berthing against the platform or by

drilling operations

5.2 Loading Conditions

5.2.1 General

Design environmental load conditions are those forces imposed on the platforms by the selected design

event, whereas operating environmental load conditions are those forces imposed on the structure by a

lesser event that is not severe enough to restrict normal operations, as specified by the operator

5.2.2 Design Loading Conditions

The platform should be designed for the appropriate loading conditions that produce the most severe

effects on the structure The loading conditions should include environmental conditions combined with

appropriate dead and live loads as indicated in Table 5.1

Table 5.1—Design Loading Conditions Loading

1 Operating environmental conditions combined with dead loads and maximum live loads appropriate to normal operations of the platform

2 Operating environmental conditions combined with dead loads and minimum live loads appropriate to the normal operations of the platform

3 Design environmental conditions with dead loads and maximum live loads appropriate for combining with extreme conditions

4 Design environmental conditions with dead loads and minimum live loads appropriate for combining with extreme conditions

Environmental loads, with the exception of earthquake load, should be combined in a manner consistent

with the probability of their simultaneous occurrence during the loading condition being considered

Earthquake load, where applicable, should be imposed on the platform as a separate environmental loading condition

The operating environmental conditions should be representative of moderately severe conditions at the platform They should not necessarily be limiting conditions that, if exceeded, require the cessation of platform operations Typically, a 1-year to 10-year winter storm is used as an operating condition in the Gulf of Mexico API 2MET or site-specific data developed in accordance with the requirements of API 2MET shall be used for specific values of the associated environmental conditions

Maximum live loads for drilling and production platforms should consider drilling, production, and workover mode loadings and any appropriate combinations of drilling or workover operations with production

Variations in supply weights and the locations of movable equipment such as a drilling derrick should be considered to maximize design stress in the platform members

5.2.3 Temporary Loading Conditions

Temporary loading conditions occurring during fabrication, transportation, installation, or removal and reinstallation of the structure should be considered For these conditions a combination of the appropriate dead loads, maximum temporary loads, and the appropriate environmental loads should be considered

5.3.1.2 Static Wave Analysis

5.3.1.2.1 General

The sequence of steps in the calculation of deterministic static design wave forces on a fixed platform (neglecting platform dynamic response and distortion of the incident wave by the platform) is shown graphically in Figure 5.1 The procedure, for a given wave direction, begins with the specification of the design wave height and associated wave period, storm water depth, and current profile The parameters for U.S waters specified in API 2MET or site-specific data developed in accordance with the requirements of API 2MET shall be used The wave force calculation procedure follows these steps 1) An apparent wave period is determined, accounting for the Doppler effect of the current on the wave

2) The two-dimensional wave kinematics are determined from an appropriate wave theory for the

specified wave height, storm water depth, and apparent period

3) The horizontal components of wave-induced particle velocities and accelerations are reduced by the

wave kinematics factor, which accounts primarily for wave directional spreading

4) The effective local current profile is determined by multiplying the specified current profile by the

current blockage factor

5) The effective local current profile is combined vectorially with the wave kinematics to determine

locally incident fluid velocities and accelerations for use in Morison’s equation

6) Member dimensions are increased to account for marine growth

7) Drag and inertia force coefficients are determined as functions of wave and current parameters,

member shape, roughness (marine growth), size, and orientation

8) Wave force coefficients for the conductor array are reduced by the conductor shielding factor

9) Hydrodynamic models for risers and appurtenances are developed

10) Local wave/current forces are calculated for all platform members, conductors, risers, and

appurtenances using Morison’s equation

11) The global force is computed as the vector sum of all the local forces

The discussion in the remainder of this section is in the same order as the steps listed above There is

also some discussion on local forces (such as slam and lift) that are not included in the global force

Figure 5.1—Procedure for Calculation of Wave Plus Current Forces for Static Analysis

5.3.1.2.2 Apparent Wave Period

A current in the wave direction tends to stretch the wavelength, while an opposing current shortens it For the simple case of a wave propagating on a uniform in-line current, the apparent wave period seen by an

observer moving with the current can be estimated from Figure 5.2, in which T is the actual wave period (as seen by a stationary observer) Vi is the current component in the wave direction, d, is storm water depth (including storm surge and tide), and g is the acceleration of gravity This figure provides estimates

for d g T2 > 0.01 For smaller values of d g T2 , the equation (Tapp T)= +1 V g di

can be used While strictly applicable only to a current that is uniform over the full water depth, Figure 5.2 provides

acceptable estimates of Tapp for “slab” current profiles that are uniform over the top 50 m (165 ft) or more

of the water column For other current profiles, Tapp (see B.5.3.1.2.2) is generally determined from the

iterative solution of a system of simultaneous nonlinear equations The current used to determine Tapp

should be the free-stream current (not reduced by structure blockage)

Key

d gT2 = 0.01 + 0.02 0.04

∆ 0.10

Figure 5.2—Doppler Shift Due to Steady Current

5.3.1.2.3 Two-dimensional Wave Kinematics

For the apparent wave period Tapp, specified wave height H, and storm water depth, d, two-dimensional

regular wave kinematics can be calculated using the appropriate order of stream function wave theory In

many cases, Stokes V wave theory produces acceptable accuracy Figure 5.3 shows the regions of

applicability of Stokes V and various orders of stream function solutions in the H g Tapp2 , d g Tapp2 plane

Other wave theories, such as extended velocity potential and Chappelear, may be used if an appropriate

order of solution is selected

5.3.1.2.4 Wave Kinematics Factor

The two-dimensional regular wave kinematics from stream function or Stokes V wave theory do not

account for wave directional spreading or irregularity in wave profile shape These “real world” wave

characteristics can be approximately modeled in deterministic wave analyses by multiplying the horizontal

velocities and accelerations from the two-dimensional regular wave solution by a wave kinematics factor

Wave kinematics measurements support a factor in the range 0.85 to 0.95 for tropical storms and 0.95 to

1.00 for extratropical storms Particular values within these ranges that shall be used for calculating

guideline wave forces are specified for the Gulf of Mexico and for other U.S waters in API 2MET Section

B.5.3.1.2.4 provides additional guidance for calculating the wave kinematics factor for particular sea

states whose directional spreading characteristics are known from measurements or hindcasts

5.3.1.2.5 Current Blockage Factor

The current speed in the vicinity of the platform is reduced from the specified “free stream” value by

blockage In other words, the presence of the structure causes the incident flow to diverge; some of the

incident flow goes around the structure rather than through it, and the current speed within the structure is

reduced Since global platform loads are determined by summing local loads from Morison’s equation, the

appropriate local current speed should be used Table 5.2 gives typical current blockage factors for Gulf

of Mexico jacket platforms

For structures with other configurations or structures with a typical number of conductors, a current

blockage factor can be calculated with the method described in B.5.3.1.2.5 Calculated factors less than

0.7 should not be used without empirical evidence to support them For freestanding or braced caissons

the current blockage factor should be 1.0

Table 5.2—Approximate Current Blockage Factors for Typical Gulf of Mexico Jacket-type Structures

Number of Legs Heading Factor

4

end-on 0.80 diagonal 0.85 broadside 0.80

6

end-on 0.75 diagonal 0.85 broadside 0.80

8

end-on 0.70 diagonal 0.85 broadside 0.80

Figure 5.3—Regions of Applicability of Stream Function, Stokes V, and Linear Wave Theory

(from Atkins, 1990; Modified by API Task Group on Wave Force Commentary)

H gTapp2

Deep Water Break i ng Limit -

d: Mean wate r depth

T a p p: Wave pe rio d g: Accelera tion of g r avity